Well control

ABSTRACT

A method of isolating a reservoir of production fluid in a formation comprises providing a pair of valves ( 14, 16 ) in a bore intersecting a production formation and in which the hydrostatic pressuer in the bore at the formation is normally lower than the formation pressure, and then ontrolling the valves ( 14, 16 ) from surface such that the valves ( 14, 16 ) will only move from a closed configuration to an open configuration on experiencing a predetermined differential pressure across the valves.

[0001] This invention relates to well control, and in particular to amethod and apparatus for use in controlling access and flow to and froma subsurface well.

[0002] In the oil and gas exploration and production industry, bores aredrilled to access subsurface hydrocarbon-bearing formations. The oil orgas in the production formation is under pressure, and to preventuncontrolled flow of oil or gas from the formation to the surface, thatis a “blowout”, it has been conventional to fill the bore above theformation with fluid of sufficient density that the hydrostatic pressurehead provided by the column of fluid retains the oil or gas in theformation. However, it has been recognised that this practice may resultin damage to the formation, and may significantly reduce theproductivity of the formation. This problem has recently come to thefore as deeper and longer bores are drilled, and thus the hydrostaticpressure of drilling fluid or “mud” increases, and further as thepressures necessary to circulate drilling fluid and entrain cuttings inthe conventional manner increases.

[0003] One result of these experiences and findings has been thedevelopment of technology and methods which permit “under-balanced”drilling, that is a drilling operation in which the pressure of thedrilling fluid is lower than the formation fluid pressure, such that oiland gas may flow from the formation and commingle with the drillingfluid. The fluids travel together to the surface and are separated atsurface. In many cases, use of underbalanced drilling has resulted inmarked increases in well productivity.

[0004] However, one difficulty associated with underbalanced drilling isthe relatively high fluid pressures that are experienced at surface.This places an increased reliance on surface sealing arrangements, andgenerally increases the difficulty in controlling the well; theconventional high density fluid column is not present, and in the eventof difficulties, pumping higher density fluid into the well to “kill” orcontrol the well may take some time and is likely to result in damage tothe formation, perhaps to an extent where the well must be abandoned.

[0005] There is also a difficulty associated with making up drill stringand the like to be run into such wells, or indeed in any well where thepressure at surface is relatively high. In such wells, the relativelyhigh fluid pressure (which may be several hundred atmospheres) will tendto push the drill string up and out of the well, such that making upsuch a string becomes a difficult and potentially dangerous operation.This difficulty persists until the weight of the string is sufficient tocounteract the pressure force.

[0006] It has been proposed to avoid or overcome at least some of thesedifficulties by placing a flapper valve in a lower section of a well,the valve closing when the pressure forces acting from below the valveare greater than the pressure forces acting from above the valve. Thisplaces restrictions of the placement of the valve which, to beeffective, must be located close to the pressure balance point in thewell, that is the point where the upward acting fluid pressure force, orreservoir pressure, equals the downward acting force from the pressurehead produced by the column of fluid in the bore. Further, while such avalve may assist in preventing uncontrolled flow from a formation, thevalve will not serve to protect a formation from damage or contaminationin the event that the pressure above the valve rises; in such asituation elevated pressure above the valve will tend to open the valve.Similarly, testing the valve presents difficulties, as higher testpressures will tend to open the valve, and therefore no pressure greaterthan reservoir pressure may be safely utilised, as a higher pressurewould run the risk of damaging the formation.

[0007] It is among the objectives of embodiments of the presentinvention to obviate or mitigate these disadvantages.

[0008] According to one aspect of the present invention there isprovided a method of isolating a reservoir of production fluid in aformation, the method comprising:

[0009] providing a valve in a bore intersecting a production formationand in which the hydrostatic pressure in the bore at the reservoir isnormally lower than the formation pressure; and

[0010] controlling the valve from surface such that the valve will onlymove from a closed configuration to an open configuration onexperiencing a predetermined differential pressure thereacross.

[0011] The invention also relates to an apparatus for use in isolating areservoir of production fluid in a formation, the apparatus comprising:

[0012] a valve adapted for location in a bore intersecting a productionformation and in which the hydrostatic pressure in the bore at thereservoir is normally lower than the formation pressure;

[0013] first valve control means for permitting control of the valvefrom surface; and

[0014] second valve control means for permitting control of movement ofthe valve from a closed to an open configuration in response to apredetermined differential pressure across the valve.

[0015] Preferably, the valve is controlled such that it will only openwhen there is little or no pressure differential across the valve. Thus,as the valve opens there is little if any flow of fluid through thevalve as the pressure equalises; opening the valve in the presence of apressure differential may result in the rapid flow of fluid through thevalve as it opens, with an increased likelihood of erosion and damage tothe valve. In under-balanced and live well applications this allows thevalve to hold pressure from one or both sides, and minimises the risk offormation damage or contamination when the pressure above the valve ishigher than the pressure below the valve. Further, this feature may beutilised to minimise the risk of uncontrolled flow of fluid from theformation, in the event of pressure below the valve being higher thanthe pressure above the valve.

[0016] The valve may be positioned above, at or below the pressurebalance point.

[0017] Preferably, the valve is controlled from surface by fluidpressure, the control fluid supply of gas or liquid being isolated fromthe well fluid, for example in control lines or in a parasitic annulus.The valve may include a control fluid piston, application of controlfluid thereto tending to close the valve. Preferably, the valve isfurther also responsive to well fluid pressure, and in particular to thedifferential well fluid pressure across the valve, such that the closedvalve will remain closed or will open in response to a selected controlpressure in combination with a selected differential pressure. The valvemay include a piston in communication with fluid below the valve and apiston in communication with fluid above the valve; application ofpressure to the former may tend to close the valve, while application ofpressure to the latter may tend to open the valve. In a preferredembodiment, a selected first control pressure will close the valve. Sucha first control pressure in combination with a higher pressure below thevalve will tend to maintain the valve closed. Further, increasing thecontrol pressure will maintain the valve closed in response to a higherpressure above the valve. This facility also allows the applied controlpressure to be brought to a particular value, the pressure differentialacross the valve to be minimised and the control fluid pressure thenvaried to allow the valve to open.

[0018] Preferably, the valve is a ball valve. However, the valve mayalso be a flapper valve, or indeed any form of valve appropriate to theapplication.

[0019] Preferably, the valve comprises two valve closure members, whichmay be two ball valves, two flapper valves, or even a combination ofdifferent valve types. The valves may have independent operatingmechanisms. The valve closure members may close simultaneously, or insequence, and preferably the lowermost valve member closes first. Thisallows the valves to be pressure-tested individually. Sequenced closingmay be achieved by, for example, providing the valve members incombination with respective spring packs with different pre-loads.

[0020] Preferably, the valve is run into a cased bore on intermediate orparasitic casing, thus defining a parasitic annulus, between theexisting casing and the parasitic casing, via which control pressure maybe communicated to the valve. The parasitic casing is sealed to thebore-lining casing at or below the valve, typically using a packer orother sealing arrangement. The parasitic annulus may be used to carryfluids, for example to allow nitrogen injection in the well below thevalve. For example, additional casing may be hung off below the valve toextend the parasitic annulus, and a pump open\pump closed nitrogeninjection valve provided to selectively isolate the parasitic annulusfrom the well bore annulus. In other embodiments the parasitic annulusmay be utilised to carry gas or fluid lift gas or fluid to a point inthe well above the valve, or even between a pair of valves. One or moreone-way valves may be provided and which may be adapted to open at aparasitic pressure in excess of that required to close the valve orperform pressure tests above the valve. Such an arrangement may beutilised to circulate out a column of well kill fluid, prior to openingthe valve, or alternatively to inject a fluid slug prior to opening thevalves, or to inject methanol from the parasitic annulus to preventhydrate formation.

[0021] The valve may be configured to allow the valve to be locked open,for example by locating a sleeve in the open valve.

[0022] The valve may be configured to permit pump-though, that is, onexperiencing a sufficiently high pressure from above, the valve may bemoved, for example partially rotated in the case of a ball valve, topermit fluid flow around the nominally closed valve.

[0023] According to another aspect of the present invention there isprovided an apparatus for use in isolating a reservoir of productionfluid in a formation, the apparatus comprising:

[0024] a valve adapted for location in a bore intersecting a productionformation and in which the hydrostatic pressure in the bore at thereservoir is normally lower than the formation pressure; and

[0025] first valve control means for permitting control of the valvefrom surface,

[0026] the valve including two valve closure members, both valve closuremembers being adapted to hold pressure both from above and from below.

[0027] Preferably, the valve closure members are ball valves.Alternatively, the valve closure members are flapper valves.

[0028] Preferably, the valve closure members are independently operable.

[0029] These and other aspects of the present invention will now bedescribed, by way of example, with reference to the accompanyingdrawings, in which:

[0030]FIG. 1 is a schematic illustration of apparatus for use inisolating a reservoir in accordance with a preferred embodiment of thepresent invention, shown located in a well;

[0031]FIG. 2 is an enlarged sectional view of valves of the apparatus ofFIG. 1; and

[0032]FIG. 3 is a further enlarged sectional view of one of the valvesof the apparatus of FIG. 1.

[0033] Reference is first made to FIG. 1 of the drawings, which is aschematic illustration of apparatus 10 for use in isolating a reservoirin accordance with a preferred embodiment of the present invention, theapparatus 10 being shown located in a well 12. The illustrated wellfeatures three main sections, that is a 17½ inch diameter hole sectionlined with 13⅜ inch diameter casing, a 12¼ inch hole section lined with9⅝ inch casing, and an 8½ inch hole section lined with 7 inch casing;those of skill in the art will of course recognise that these dimensionsare merely exemplary, and that the apparatus 10 may be utilised in awide variety of well configurations. The apparatus 10 is located withinthe larger diameter first well section and comprises upper and lowervalves 14, 16. As will be described, the valves 14, 16 are similar, withonly minor differences therebetween. The valves are mounted on tubing 18which extends from the surface, through a rotating blow-out preventer(BOP) 20, an annular preventer 22, and a standard BOP 24. Anintermediate tubular connector 26 joins the valves 14, 16, and a furthersection of tubing 28 extends from the lower valve 16, through the 9⅝inch casing, to engage and seal with the upper end of the 7 inch casing.Thus, an isolated annulus 30 is formed between the valves 14, 16 and thetubing 18, 28, and the surrounding casing; this will be referred to asthe parasitic annulus 30.

[0034] The apparatus 10 will be described with reference to anunder-balanced drilling operation, and in such an application a tubulardrill string will extend from surface through the valves 14, 16 and thetubing 18, 28.

[0035] Reference is now also made to FIG. 2 of the drawings, which is anenlarged sectional view of the valves 14, 16, shown separated. Referencewill also be made to FIG. 3 of the drawings which is an enlargedsectional view of the lower valve 16. As the only differences betweenthe valves 14, 16 is the pre-loading on the valve closing spring and thearrangement of porting for valve control fluid, only one of the valves16 will be described in detail, as exemplary of both. The valve 16 is aball valve and therefore includes a ball 34 located within a generallycylindrical valve body 36, and in this example the ends of the body 36feature male premium connections 38 for coupling to the tubing section18 and the connector 26.

[0036] The ball 34 is mounted in a ball cage 40 which is axially movablewithin the valve body 36 to open or close the valve. The valve 16 isillustrated in the closed position. Above the cage 40 is an upper piston42 which is responsive to fluid pressure within the tubing 18 above thevalve 14, communicated via porting 43. Further, a power spring 44 islocated between the piston 42 and a top plate 46 which is fixed relativeto the valve body 36. Accordingly, the spring 44, and fluid pressureabove the ball 34, will tend to move the valve ball 34 to the openposition.

[0037] Below the cage 40 is a lower piston 48 which, in combination withthe valve body 36, defines two piston areas, one 50 in fluidcommunication with the parasitic annulus 30, via porting 51, and theother 52 in communication, via porting 53, with the tubing below thevalves 14, 16, that is the reservoir pressure

[0038] In use, in the absence of any pressure applied to the valves 14,16 via the parasitic annulus 30, the springs 44 will urge the valveballs 34 to the open position, allowing flow through the valves 14, 16.If however it is desired to close the valve, the pressure in theparasitic annulus 30 is increased, to increase the force applied to theparasitic pistons 50. The pre-load on the spring 44 in the lower valve16 is selected to be lower than the pre-load of the spring 44 in theupper valve 14, such that the lower valve 16 will close first. Thus, theeffectiveness of the seal provided by the lower valve 16 may beverified. A further increase in pressure in the parasitic annulus 30will then also close the upper valve 14.

[0039] The valve balls 34 are designed to permit cutting or shearing oflightweight supports such as slickline, wireline or coiled tubing,passing through the apparatus 10, such that the valves may be closedquickly in an emergency situation without having to withdraw a supportform the bore.

[0040] With the valves 14, 16 closed, the reservoir is now isolated fromthe upper section of the well. This facilitates various operations,including the retrieval, making up and running in of tools, devices andtheir support strings above the apparatus 10, or the circulation offluids within the upper end of the tubing 18 to, for example, fill thetubing 18 with higher or lower density fluid.

[0041] In the event that the reservoir pressure below the valves 14, 16is higher than the pressure in the tubing 18 above the valves 16, 18,the reservoir pressure acting on the pistons 52 will tend to maintainthe valves 14, 16 closed, thus preventing uncontrolled flow of formationfluids from the reservoir.

[0042] In the event that the pressure differential is reversed, that isthe pressure force above the valves 14, 16 is greater than the reservoirpressure acting below the valves 14, 16, the parasitic pressure may beincreased to increase the valve closing force acting on the pistons 50,to counteract the valve opening force acting on the pistons 42.

[0043] The area of the upper piston 42 is equal to the combined areas ofthe parasitic and reservoir pistons 50, 52, while the parasitic piston50 is larger than the reservoir piston 52. Thus, if it is desired toopen the valve from a closed position, this is normally achieved byincreasing the pressure in the parasitic annulus 30 to a point where theparasitic pressure is substantially similar to the reservoir pressure.The pressure in the tubing 18 is then increased, and as the tubingpressure approaches the reservoir pressure the forces acting on thepistons 42 reach a level similar to the oppositely acting forces on thelower pistons 48, such that the springs 44 will tend to open the valveswhen the parasitic pressure is vented at surface.

[0044] While the parasitic pressure remains vented, the springs 44 willretain the valves open.

[0045] With this arrangement it would be possible to open the valveswhen the tubing pressure above the valves 14, 16 was lower thanreservoir pressure, if the parasitic pressure was not increased to begreater or equal to the reservoir pressure. However, this would resultin the valves 14, 16 opening with a pressure differential, and theresulting rapid flow of fluid through the valves would bring an increaselikelihood of erosion and damage to the valves and upstream equipment.

[0046] In the event that one or both of the valves cannot be opened, andit is desired to, for example, “kill” the well, it sufficient tubingpressure is applied from surface the valve balls 34 will be pusheddownwardly to an extent that kill fluid may pass around the balls 34 andthen out of pump-through ports 54 provided in the lower ball seats 56.

[0047] If desired, one or more one-way valves may be provided in thetubing 28 or valve body 36. For example, one or more one-way pressurerelief valves may be provided above the upper valve 14, and configuredto pass gas or fluid from the parasitic annulus into the tubing 18. Sucha valve positioned just above or between the valves 14, 16 may be usedto, for example, circulate out a column of well kill fluid prior toopening the valve, or to inject a fluid slug prior to opening thevalves. Such a valve could also be used to inject methanol from theparasitic annulus 30 on top of the upper valve 14 to prevent hydrateformation. Alternatively, a one-way valve could be incorporated betweenthe valves 14, 16. Of course, such a valve or valves would only open inresponse to a parasitic annulus pressure in excess of that required toclose the valves, to perform a pressure test from above a closed valve,or to support a column of well kill fluid above the valves.

[0048] In the illustrated embodiment the provision of the parasiticannulus may also be used to advantage to, for example, allow nitrogeninjection in the well below the apparatus 10. For example, a nitrogeninjection point could be provided on the tubing 28 below the apparatus10. Of course the injection point would have to be isolated from thetubing bore using a pump open\pump close nitrogen injection valve.

[0049] From the above description it will be apparent to those of skillin the art that the apparatus described above provides a safe andconvenient method of isolating a reservoir, and the ability of thevalves to hold pressure from both above and below is of considerableadvantage to the operator, and provides additional safeguards andconvenience in under-balanced drilling, at balance drilling or livewell\light weight intervention environments, most particularly in thedeployment of drilling assemblies, intervention assemblies, workoverassemblies, completions, liners, slotted liners or sandscreens.

[0050] Those of skill in the art will also recognise that theillustrated embodiment is merely exemplary of the present invention, andthat various modifications and improvements may be made thereto withoutdeparting from the scope of invention. For example, rather thancontrolling the operation of the valves 14, 16 via the parasitic annulus30, conventional control lines may be run from surface to supply controlfluid to the valves. Further, rather than providing valves in individualhousings, a common housing assembly for both valves could be provided.The above described valve arrangements rely primarily on metal-to-metalseals between the balls and the valve seats, and of course in otherembodiments elastomeric seals may also be provided. The valvesillustrated and described above are in the form of ball valves, thoughthose of skill in the art will recognise that flapper valves may also beutilised, particularly flapper valves having the facility to be heldclosed in response to both pressure from above and from below.

1. A method of isolating a reservoir of production fluid in a formation, the method comprising: providing a valve in a bore intersecting a production formation and in which the hydrostatic pressure in the bore at the formation is normally lower than the formation pressure; and controlling the valve from surface such that the valve will only move from a closed configuration to an open configuration on experiencing a predetermined differential pressure thereacross.
 2. The method of claim 1, wherein the valve is moved from an open configuration to a closed configuration by application of a control pressure thereto.
 3. The method of claim 1, wherein the valve is controlled such that it will only open when there is little or no pressure differential across the valve.
 4. The method of claim 3, wherein the bore is in an underbalanced or live well.
 5. The method of any of the preceding claims, wherein the closed valve is controlled to hold higher pressure above the valve.
 6. The method of any of the preceding claims, wherein the closed valve is controlled to hold higher pressure below the valve.
 7. The method of any of the preceding claims, wherein the closed valve is controlled to hold pressure from both sides.
 8. The method of any of the preceding claims, wherein the valve is positioned above the pressure balance point in the bore.
 9. The method of any of claims 1 to 7, wherein the valve is positioned at the pressure balance point.
 10. The method of any of claims 1 to 7, wherein the valve is positioned below the pressure balance point.
 11. The method of any of the preceding claims, wherein the valve is controlled from surface by fluid pressure.
 12. The method of any of the preceding claims, wherein the control fluid supply is supplied from surface to the valve through at least one control line.
 13. The method of any of claims 1 to 11, wherein the control fluid supply is supplied from surface to the valve through a parasitic annulus.
 14. The method of any of the preceding claims, wherein the valve is initially open and comprising the step of applying a selected first control pressure to close the valve.
 15. The method of claim 14, comprising applying a higher pressure below the valve to maintain the valve closed, without continued application of said control pressure.
 16. The method of claim 14, comprising applying said first control pressure in combination with a higher pressure below the valve to maintain the valve closed.
 17. The method of claim 14, 15 or 16 comprising increasing said control pressure to maintain the valve closed in response to a higher pressure above the valve.
 18. The method of any of claims 14, 15, 16 or 17, comprising bringing the applied control pressure to a particular value, minimising the pressure differential across the valve, and then varying the control fluid pressure to open the valve.
 19. The method of any of the preceding claims, comprising providing two similar valves in the bore.
 20. The method of claim 19, further comprising closing the valves simultaneously.
 21. The method of claim 19, further comprising closing the valves in sequence.
 22. The method of claim 21, further comprising closing the lowermost valve first.
 23. The method of claim 22, comprising pressure testing, the lowermost valve following closing thereof and then pressure testing the upper valve following closing thereof.
 24. The method of any of the preceding claims, comprising running the valve into a cased bore on intermediate or parasitic casing, thus defining a parasitic annulus between the existing casing and the parasitic casing.
 25. The method of claim 24, further comprising sealing the parasitic casing to the bore-lining casing at or below the valve.
 26. The method of claim 25, further comprising carrying fluids into the bore below the valve through the parasitic annulus.
 27. The method of claim 26, wherein the fluid is nitrogen and the nitrogen is injected in the bore below the valve.
 28. The method of claim 25 or 26, further comprising hanging additional casing off below the valve to extend the parasitic annulus.
 29. The method of claim 25, further comprising carrying gas, fluid lift gas or fluid to a point in the bore above the valve.
 30. The method of any of claims 25 to 29, further comprising providing at least one one-way valve between the parasitic annulus and the bore and opening the one-way valve in response to a parasitic pressure in excess of that required to function the valve or perform pressure tests on the valve.
 31. The method of claim 30, further comprising circulating out a column of well kill fluid above the valve via the parasitic annulus and the one-way valve prior to opening the valve.
 32. The method of claim 30, further comprising injecting a fluid slug via the parasitic annulus and the one-way valve prior to opening the valve.
 33. The method of claim 30, further comprising injecting methanol from the parasitic annulus to prevent hydrate formation.
 34. The method of any of the preceding claims, further comprising locking the valve open.
 35. An apparatus for use in isolating a reservoir of production fluid in a formation, the apparatus comprising: a valve adapted for location in a bore intersecting a production formation and in which the hydrostatic pressure in the bore at the formation is normally lower than the formation pressure; first valve control means for permitting control of the valve from surface; and second valve control means for permitting control of movement of the valve from a closed to an open configuration in response to a predetermined differential pressure across the valve.
 36. The apparatus of claim 35, wherein the first valve control means is operable to move the valve from the open configuration to the closed configuration.
 37. The apparatus of claim 35, wherein the valve is adapted to hold pressure from at least one side.
 38. The apparatus of claim 37, wherein the valve is adapted to hold pressure from both sides.
 39. The apparatus of any of claims 35 to 38, wherein the first valve control means is responsive to control fluid pressure.
 40. The apparatus of claim 39, in combination with at least one control fluid-carrying control line for extending between the apparatus and surface.
 41. The apparatus of claim 39, in combination with a parasitic casing for defining a control fluid-carrying parasitic annulus.
 42. The apparatus of any of claims 35 to 41, wherein the first fluid control means includes a control fluid piston, application of control fluid thereto tending to actuate the valve.
 43. The apparatus of any of claims 35 to 42, wherein the second fluid control means includes a piston in communication with fluid below the valve and a piston in communication with fluid above the valve.
 44. The apparatus of claim 43, wherein the second fluid control means is arranged such that application of pressure to the piston in communication with fluid below the valve tends to close the valve member.
 45. The apparatus of claim 43 or 44, wherein the second fluid control means is arranged such that application of pressure to the piston in communication with fluid above the valve tends to open the valve.
 46. The apparatus of any of claims 35 to 45, wherein the valve is a ball valve.
 47. The apparatus of any of claims 35 to 45, wherein the valve is a flapper valve.
 48. The apparatus of any of claims 35 to 47, wherein the valve comprises two valve closure members.
 49. The apparatus of any of claims 35 to 46, wherein the valve comprises two ball valves.
 50. The apparatus of any of claims 35 to 45, or 47, wherein the valve comprises two flapper valves.
 51. The apparatus of any of claims 48, 49 or 50, wherein the valves have independent operating mechanisms.
 52. The apparatus of claim 51, wherein the valves comprise respective valve members in combination with respective spring packs with different pre-loads.
 53. The apparatus of any of claims 35 to 52, wherein the valve is configured to allow the valve to be locked open.
 54. The apparatus of any of claims 35 to 53, wherein the valve is configured to permit pump-though when in the closed configuration.
 55. An apparatus for use in isolating a reservoir of production fluid in a formation, the apparatus comprising: a valve adapted for location in a bore intersecting a production formation and in which the hydrostatic pressure in the bore at the formation is normally lower than the formation pressure; and first valve control means for permitting control of the valve from surface, the valve including two valve closure members, both valve closure members being adapted to hold pressure both from above and from below.
 56. The apparatus of claim 55, wherein the valve closure members are ball valves.
 57. The apparatus of claim 55, wherein the valve closure members are ball valves.
 58. The apparatus of claim 55, 56 or 57, wherein the valve closure members are independently operable. 